Document and Document Entity In
Document and Document Entity Information - USD ($) | 9 Months Ended | ||
Sep. 30, 2016 | Oct. 14, 2016 | Jun. 30, 2016 | |
Entity Information [Line Items] | |||
Entity Registrant Name | NORTHWESTERN CORPORATION | ||
Entity Central Index Key | 73,088 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-Q | ||
Document Period End Date | Sep. 30, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | Q3 | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 48,327,642 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 3,046,980,000 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Revenues | ||||
Electric | $ 266,629 | $ 238,513 | $ 756,374 | $ 695,921 |
Gas | 34,369 | 34,226 | 170,283 | 193,389 |
Total Revenues | 300,998 | 272,739 | 926,657 | 889,310 |
Operating Expenses | ||||
Cost of sales | 96,156 | 73,577 | 293,283 | 265,495 |
Operating, general and administrative | 68,290 | 79,296 | 220,730 | 222,139 |
Property and other taxes | 40,673 | 35,712 | 111,302 | 100,953 |
Depreciation and depletion | 39,763 | 35,693 | 119,551 | 107,239 |
Total Operating Expenses | 244,882 | 224,278 | 744,866 | 695,826 |
Operating Income | 56,116 | 48,461 | 181,791 | 193,484 |
Interest Expense, net | (21,049) | (22,043) | (71,979) | (68,101) |
Other (Loss) Income | (121) | 3,769 | 4,176 | 5,429 |
Income Before Income Taxes | 34,946 | 30,187 | 113,988 | 130,812 |
Income Tax Benefit (Expense) | 9,659 | (6,389) | 4,240 | (24,616) |
Net Income | $ 44,605 | $ 23,798 | $ 118,228 | $ 106,196 |
Average Common Shares Outstanding | 48,314,783 | 47,065,082 | 48,288,678 | 47,028,924 |
Basic Earnings per Average Common Share | $ 0.92 | $ 0.51 | $ 2.45 | $ 2.26 |
Diluted Earnings per Average Common Share | 0.92 | 0.51 | 2.44 | 2.25 |
Dividends Declared per Common Share | $ 0.50 | $ 0.48 | $ 1.50 | $ 1.44 |
CONDENSED CONSOLIDATED STATEME3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Comprehensive Income (Loss) | ||||
Net Income | $ 44,605 | $ 23,798 | $ 118,228 | $ 106,196 |
Other comprehensive income (loss), net of tax: | ||||
Foreign currency translation | 26 | 233 | (84) | 445 |
Cash flow hedges: | ||||
Reclassification of net gains on derivative instruments | (1,506) | (555) | (1,432) | (735) |
Other comprehensive loss | (1,480) | (322) | (1,516) | (290) |
Comprehensive Income | $ 43,125 | $ 23,476 | $ 116,712 | $ 105,906 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEET - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Current Assets: | ||
Cash and cash equivalents | $ 5,063 | $ 11,980 |
Restricted cash | 6,706 | 6,634 |
Accounts receivable, net | 116,821 | 154,410 |
Inventories | 54,311 | 53,458 |
Regulatory assets | 44,501 | 51,348 |
Other | 10,937 | 8,830 |
Total current assets | 238,339 | 286,660 |
Property, plant, and equipment, net | 4,161,993 | 4,059,499 |
Goodwill | 357,586 | 357,586 |
Regulatory assets | 592,432 | 517,223 |
Other noncurrent assets | 43,591 | 43,727 |
Total Assets | 5,393,941 | 5,264,695 |
Current Liabilities: | ||
Current maturities of capital leases | 1,942 | 1,837 |
Short-term borrowings | 222,311 | 229,874 |
Accounts payable | 57,217 | 74,511 |
Accrued expenses | 241,185 | 183,988 |
Regulatory liabilities | 24,159 | 80,990 |
Total current liabilities | 546,814 | 571,200 |
Long-term capital leases | 24,859 | 26,325 |
Long-term debt | 1,794,519 | 1,768,183 |
Deferred income taxes | 575,812 | 501,532 |
Noncurrent regulatory liabilities | 392,857 | 378,711 |
Other noncurrent liabilities | 410,273 | 418,570 |
Total Liabilities | 3,745,134 | 3,664,521 |
Commitments and Contingencies (Note 13) | ||
Shareholders' Equity: | ||
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 51,956,936 and 48,327,642 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued | 520 | 518 |
Treasury stock at cost | (95,852) | (93,948) |
Paid-in capital | 1,381,930 | 1,376,291 |
Retained earnings | 372,321 | 325,909 |
Accumulated other comprehensive loss | (10,112) | (8,596) |
Total Shareholders' Equity | 1,648,807 | 1,600,174 |
Total Liabilities and Shareholders' Equity | $ 5,393,941 | $ 5,264,695 |
CONDENSED CONSOLIDATED BALANCE5
CONDENSED CONSOLIDATED BALANCE SHEET PARENTHETICAL | Sep. 30, 2016$ / sharesshares |
Common Stock, Par or Stated Value Per Share | $ / shares | $ 0.01 |
Common Stock, Shares Authorized | 200,000,000 |
Common Stock, Shares, Issued | 51,956,936 |
Common Stock, Shares, Outstanding | 48,327,642 |
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 0.01 |
Preferred Stock, Shares Authorized | 50,000,000 |
Preferred Stock, Shares Issued | 0 |
Preferred Stock, Shares Outstanding | 0 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
OPERATING ACTIVITIES: | ||
Net Income | $ 118,228 | $ 106,196 |
Items not affecting cash: | ||
Depreciation and depletion | 119,551 | 107,239 |
Amortization of debt issue costs, discount and deferred hedge gain | 907 | 1,301 |
Stock-based compensation costs | 4,474 | 3,275 |
Equity portion of allowance for funds used during construction | (3,053) | (6,568) |
Gain on disposition of assets | (15) | (28) |
Deferred income taxes | (4,720) | 27,019 |
Changes in current assets and liabilities: | ||
Restricted cash | (72) | (735) |
Accounts receivable | 37,589 | 46,025 |
Inventories | (853) | (3,598) |
Other current assets | (2,107) | 4,006 |
Accounts payable | (16,568) | (21,655) |
Accrued expenses | 60,852 | 19,307 |
Regulatory assets | 6,847 | 8,985 |
Regulatory liabilities | (56,831) | 12,739 |
Other noncurrent assets | (4,234) | (2,240) |
Other noncurrent liabilities | (2,007) | 3,209 |
Cash Provided by Operating Activities | 257,988 | 304,477 |
INVESTING ACTIVITIES: | ||
Property, plant, and equipment additions | (203,998) | (203,324) |
Acquisitions | 0 | (143,328) |
Proceeds from sale of assets | 1,352 | 30,209 |
Change in restricted cash | 0 | 11,758 |
Cash Used in Investing Activities | (202,646) | (304,685) |
FINANCING ACTIVITIES: | ||
Treasury stock activity | (727) | (829) |
Dividends on common stock | (71,816) | (67,145) |
Issuance of long-term debt | 249,660 | 270,000 |
Repayments on long-term debt | (225,205) | (150,024) |
Repayments of short-term borrowings, net | (7,563) | (49,897) |
Financing costs | (6,608) | (12,124) |
Cash Used in Financing Activities | (62,259) | (10,019) |
Decrease in Cash and Cash Equivalents | (6,917) | (10,227) |
Cash and Cash Equivalents, beginning of period | 11,980 | 20,362 |
Cash and Cash Equivalents, end of period | 5,063 | 10,135 |
Cash (received) paid during the period for: | ||
Income taxes | (2,922) | 27 |
Interest | 56,118 | 52,106 |
Significant non-cash transactions: | ||
Capital expenditures included in trade accounts payable | $ 11,803 | $ 8,932 |
CONSOLIDATED STATEMENTS OF SHAR
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY Statement - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Treasury Stock [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Loss [Member] | Shareholders' Equity [Member] |
Balance, shares at Dec. 31, 2014 | 50,522 | 3,607 | |||||
Balance, beginning of period at Dec. 31, 2014 | $ 505 | $ 1,313,844 | $ (92,558) | $ 264,758 | $ (8,766) | $ 1,477,783 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net Income | $ 106,196 | 0 | 0 | 0 | 106,196 | 0 | 106,196 |
Foreign currency translation adjustment | 445 | 0 | 0 | 0 | 0 | 445 | 445 |
Reclassification of net (losses) gains on derivative instruments from OCI to net income, net of tax | $ (735) | $ 0 | 0 | $ 0 | 0 | (735) | (735) |
Stock based compensation, shares | 166 | 0 | |||||
Stock based compensation, value | $ 0 | 3,304 | $ (1,926) | 0 | 0 | 1,378 | |
Issuance of shares | 0 | ||||||
Issuance of shares, value | $ 2 | 0 | 0 | ||||
Adjustments to additional paid in capital, stock issued, issuance costs | 469 | ||||||
Stock issued, value, net of fees | 924 | ||||||
Issuance of shares, treasury stock | 13 | ||||||
Issuance of shares, treasury stock, value | $ 453 | ||||||
Dividends on common stock | 0 | 0 | 0 | (67,145) | 0 | (67,145) | |
Dividends per share | $ 1.44 | ||||||
Balance, end of period at Sep. 30, 2015 | $ 507 | 1,317,617 | $ (94,031) | 303,809 | (9,056) | 1,518,846 | |
Balance, shares at Sep. 30, 2015 | 50,688 | 3,620 | |||||
Balance, shares at Dec. 31, 2015 | 51,789 | 3,617 | |||||
Balance, beginning of period at Dec. 31, 2015 | $ 1,600,174 | $ 518 | 1,376,291 | $ (93,948) | 325,909 | (8,596) | 1,600,174 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net Income | 118,228 | 0 | 0 | 0 | 118,228 | 0 | 118,228 |
Foreign currency translation adjustment | (84) | 0 | 0 | 0 | 0 | (84) | (84) |
Reclassification of net (losses) gains on derivative instruments from OCI to net income, net of tax | $ (1,432) | $ 0 | 0 | $ 0 | 0 | (1,432) | (1,432) |
Stock based compensation, shares | 168 | 13 | |||||
Stock based compensation, value | $ 0 | 5,650 | $ (1,904) | 0 | 0 | 3,746 | |
Issuance of shares | 0 | ||||||
Issuance of shares, value | $ 2 | 0 | 0 | ||||
Adjustments to additional paid in capital, stock issued, issuance costs | (11) | ||||||
Stock issued, value, net of fees | (9) | ||||||
Issuance of shares, treasury stock | 0 | ||||||
Issuance of shares, treasury stock, value | |||||||
Dividends on common stock | 0 | 0 | 0 | (71,816) | 0 | (71,816) | |
Dividends per share | $ 1.50 | ||||||
Balance, end of period at Sep. 30, 2016 | $ 1,648,807 | $ 520 | $ 1,381,930 | $ (95,852) | $ 372,321 | $ (10,112) | $ 1,648,807 |
Balance, shares at Sep. 30, 2016 | 51,957 | 3,630 |
Nature of Operations and Basis
Nature of Operations and Basis of Consolidation | 9 Months Ended |
Sep. 30, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block] | Nature of Operations and Basis of Consolidation NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 701,000 customers in Montana, South Dakota and Nebraska. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to September 30, 2016 , have been evaluated as to their potential impact to the Financial Statements through the date of issuance. The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2015 . Variable Interest Entities A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain Qualifying Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $252.9 million through 2024 . |
New Accounting Standards
New Accounting Standards | 9 Months Ended |
Sep. 30, 2016 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Pronouncements [Text Block] | New Accounting Standards Accounting Standards Issued In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The FASB delayed the effective date of this guidance to the first quarter of 2018, with early adoption permitted as of the original effective date of the first quarter of 2017. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures. In February 2016, the FASB issued revised guidance on accounting for leases. The new standard requires a lessee to recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases with terms longer than 12 months. Leases with a term of 12 months or less will be accounted for similar to existing guidance for operating leases. Recognition, measurement and presentation of expenses will depend on classification as a finance or operating lease. The new guidance will be effective for us in our first quarter of 2019 and early adoption is permitted. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the impact of adoption of this guidance, and based on our initial analysis do not expect it to have a significant impact on our Financial Statements and disclosures. In March 2016, the FASB issued guidance revising certain elements of the accounting for share-based payments. The new standard is intended to simplify several aspects of the accounting for share-based payment award transactions including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. The new guidance will be effective for us in our first quarter of 2017, with early adoption permitted. We are currently evaluating the impact of adoption of this guidance on our Financial Statements and disclosures. In August 2016, the FASB issued guidance that addresses eight classification issues related to the presentation of cash receipts and cash payments in the statement of cash flows. The new guidance will be effective for us in our first quarter of 2018, with early adoption permitted. We are currently evaluating the impact of adoption of this guidance on our Statement of Cash Flows. Accounting Standards Adopted In February 2015, the FASB issued consolidation guidance that eliminated two consolidation models and requires all legal entities to be evaluated under a voting interest entity model or a variable interest entity model. Both models require the reporting entity to identify whether it has a controlling financial interest in a legal entity and is therefore required to consolidate the entity. We adopted this guidance during the first quarter of 2016 with no material impact to our Financial Statements and disclosures. In April 2015, the FASB issued accounting guidance that changes the presentation of debt issuance costs. The core principle of this revised accounting guidance is that debt issuance costs are not assets, but adjustments to the carrying cost of debt. During the first quarter of 2016, we retrospectively adopted this guidance. The implementation of this accounting standard resulted in a reduction of other noncurrent assets and long-term debt of $13.9 million and $13.0 million in the Condensed Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively. |
Regulatory Matters
Regulatory Matters | 9 Months Ended |
Sep. 30, 2016 | |
Regulated Operations [Abstract] | |
Public Utilities Disclosure [Text Block] | Regulatory Matters Montana Natural Gas Delivery and Production Rate Filing In September 2016, we filed a natural gas rate case with the Montana Public Service Commission (MPSC) requesting an annual increase to natural gas rates of approximately $10.9 million , which includes approximately $7.4 million for delivery service and approximately $3.5 million for natural gas production. Our request was based on a return on equity of 10.35% , rate base of $432.1 million , and a capital structure of 53% debt and 47% equity. This filing includes a request for cost-recovery of two natural gas production fields acquired in August 2012 and December 2013 in northern Montana's Bear Paw Basin, which are recovered in customer rates on an interim basis, and a request that these fields be placed in permanent rates based on the actual cost of production. Finally, we requested that approximately $5.6 million of the rate increase for delivery service be approved on an interim basis to allow recovery of costs prior to the conclusion of the full rate case. We expect to receive a decision on our interim request by the end of the first quarter of 2017. The MPSC has nine months in which to issue a final decision on our filing. Montana Electric and Natural Gas Tracker Filings Each year we submit an electric and natural gas tracker filing for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our supply procurement activities were prudent. During the second quarter of 2016, we filed our 2016 annual electric and natural gas tracker filings for the 2015/2016 tracker period. The MPSC issued orders in July 2016 approving the filings on an interim basis. Electric Trackers - 2012/2013 - 2013/2014 (Consolidated Docket) and 2014/2015 (2015 Tracker) - The MPSC held a work session in March 2016 and directed staff to draft a final order in our Consolidated Docket that reflects a disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs in each of the periods. On the same day, in a separate work session, the MPSC directed staff to draft a final order in the 2015 Tracker that approved a stipulation between us and the Montana Consumer Counsel, but disallowed portfolio modeling costs. Based on the March 2016 work sessions, we recorded a disallowance during the first quarter of 2016 totaling approximately $10.3 million , which included $8.2 million of replacement power costs and $2.1 million of modeling costs. In April 2016, we received the final written order in the 2015 Tracker, which was consistent with the work session. In May 2016, we received the final written order in the Consolidated Docket. The written order upheld the March 2016 decision regarding replacement power costs and clarified the disallowance of modeling costs, resulting in a reduction of the disallowance of $0.8 million , which was reflected as a reduction in cost of sales in the second quarter of 2016. Based on the final orders, the impact of the disallowance totals $12.4 million , which includes interest of $2.9 million and is recorded in the Condensed Consolidated Statement of Income for the nine months ended September 30, 2016 . In June 2016, we filed an appeal of the 2015 Tracker decision regarding the disallowance of portfolio modeling costs in Montana District Court (Lewis & Clark County). Also, in September 2016, we appealed the MPSC’s decisions in the Consolidated Docket regarding the disallowance of Colstrip Unit 4 replacement power costs and the modeling/planning costs, arguing that these decisions were arbitrary and capricious, and violated Montana law. We brought this action in Montana District Court, as well (Yellowstone County). While the courts are not obligated to rule on these appeals within a certain period of time, based on our experience, we believe we are likely to receive orders from the courts in these matters within 9-20 months of filing. Electric and Natural Gas Lost Revenue Adjustment Mechanism - In 2005, the MPSC approved an energy efficiency program, by which we recovered on an after-the-fact basis a portion of our fixed costs that would otherwise have been collected in kilowatt hour sales lost due to the implementation of energy saving measures. In an order issued in October 2013 related to our 2011/2012 electric supply tracker, the MPSC required us to lower the calculated lost revenue recovery and imposed a new burden of proof on us for future recovery. We appealed the October 2013 order to Montana District Court, which led to a docket being initiated in June 2014 by the MPSC to review lost revenue policy issues. In October 2015, the MPSC issued an order to eliminate the lost revenue adjustment mechanism prospectively effective December 1, 2015. Based on the October 2013 MPSC order, for the period July 1, 2012 through November 30, 2015, we recognized $7.1 million of lost revenues for each annual electric supply tracker period and deferred the remaining $14.2 million of efficiency efforts collected through the trackers pending final approval of the open tracker filings. As discussed above, during the second quarter of 2016, we received final written orders resolving our prior period open tracker dockets. These orders allowed the recovery of lost revenues included in each tracker period. As a result, we recognized revenue deferred during the July 2012 - November 2015 periods of $14.2 million in the Condensed Consolidated Statement of Income in the second quarter of 2016. Hydro Compliance Filing In December 2015, we submitted the required hydro compliance filing to remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our hydro rates based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of the Kerr Project. The MPSC identified additional issues and requested information. A hearing was held in September 2016. The only contested issue at the hearing was the level of administrative and general expenses that should be deducted from the approved revenue requirement due to the transfer of the Kerr Project. We expect the MPSC to issue a final order during the fourth quarter of 2016. The adjustment to rates is being refunded to customers over 12 months, and as of September 30, 2016 , we have deferred revenue remaining of approximately $2.6 million that we expect to refund to customers by the end of 2016. FERC Filing - Dave Gates Generating Station at Mill Creek (DGGS) In May 2016, we received an order from the Federal Energy Regulatory Commission (FERC) denying a May 2014 request for rehearing and requiring us to make refunds. The request for rehearing challenged a September 2012 FERC Administrative Law Judge's (ALJ) initial decision regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded that only a portion of these costs should be allocated to FERC jurisdictional customers. We had deferred cumulative revenue of approximately $27.3 million , consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order. In June 2016, we filed a petition for review of the FERC's May 2016 order with the United States Circuit Court of Appeals for the District of Columbia Circuit. A briefing schedule has been established, with final briefs due by the end of the first quarter of 2017. We do not expect a decision in this matter until the second half of 2017, at the earliest. The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. As of September 30, 2016 , the DGGS net property, plant and equipment is approximately $160 million . DGGS previously provided only regulation service, which is the basis for the cost allocation in our previous MPSC and FERC filings. With the addition of owned hydro generation in November 2014, we are able to shift the utilization of DGGS to additional alternative uses, optimizing our generation portfolio. In support of our biennial electricity supply resource procurement plan that we filed with the MPSC in March 2016, we conducted a portfolio optimization analysis to evaluate options to use DGGS in combination with other generation resources. This analysis indicates DGGS provides cost-effective products necessary to operate our Montana electricity portfolio, including regulation, load following, peaking services and other ancillary products such as contingency reserves, which should guide future cost recovery. The cost recovery of any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | Income Taxes The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands): Three Months Ended 2016 2015 Income Before Income Taxes $ 34,946 $ 30,187 Income tax calculated at 35% federal statutory rate 12,231 35.0 % 10,565 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (615 ) (1.8 ) (857 ) (2.8 ) Flow-through repairs deductions (18,995 ) (54.4 ) (2,779 ) (9.2 ) Production tax credits (2,218 ) (6.3 ) (733 ) (2.4 ) Plant and depreciation of flow through items (243 ) (0.7 ) (374 ) (1.2 ) Prior year permanent return to accrual adjustments — — 1,025 3.4 Other, net 181 0.6 (458 ) (1.6 ) (21,890 ) (62.6 ) (4,176 ) (13.8 ) $ (9,659 ) (27.6 )% $ 6,389 21.2 % Nine Months Ended 2016 2015 Income Before Income Taxes $ 113,988 $ 130,812 Income tax calculated at 35% federal statutory rate 39,896 35.0 % 45,784 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (2,740 ) (2.4 ) (329 ) (0.3 ) Flow-through repairs deductions (32,640 ) (28.6 ) (17,240 ) (13.2 ) Production tax credits (7,317 ) (6.4 ) (2,645 ) (2.0 ) Plant and depreciation of flow through items (1,427 ) (1.3 ) (1,000 ) (0.8 ) Prior year permanent return to accrual adjustments (128 ) (0.1 ) 1,025 0.8 Other, net 116 0.1 (979 ) (0.7 ) (44,136 ) (38.7 ) (21,168 ) (16.2 ) $ (4,240 ) (3.7 )% $ 24,616 18.8 % We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities. In 2009, we received approval from the Internal Revenue Service (IRS) to change our tax accounting method related to the repair and maintenance of transmission and distribution utility assets and have recorded a current tax deduction in our Financial Statements for each period since. In 2013, the IRS issued guidance related to the repair and maintenance of utility generation assets. During the third quarter of 2016, we filed a tax accounting method change with the IRS consistent with the guidance for generation property. This enabled us to take a current tax deduction for a significant amount of repair costs that were previously capitalized for tax purposes. As discussed above, we flow this current tax deduction through to our customers in rate cases. Consistent with this regulatory treatment, we recorded an income tax benefit of approximately $15.5 million during the three months ended September 30, 2016, of which approximately $12.5 million related to 2015 and prior tax years and is reflected in the flow-through repairs deductions line above. Uncertain Tax Positions We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately $90.0 million as of September 30, 2016 , including approximately $66.6 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months. Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the nine months ended September 30, 2016 we recognized $0.5 million of expense for interest and penalties in the Condensed Consolidated Statements of Income. As of September 30, 2016 , we had $0.5 million of interest accrued in the Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2015 , we did not recognize any expense for interest or penalties, and did not have any amounts accrued as of December 31, 2015 , for the payment of interest and penalties. Our federal tax returns from 2000 forward remain subject to examination by the Internal Revenue Service. |
Goodwill
Goodwill | 9 Months Ended |
Sep. 30, 2016 | |
Goodwill [Abstract] | |
Goodwill Disclosure [Text Block] | Goodwill We completed our annual goodwill impairment test as of April 1, 2016, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections. There were no changes in our goodwill during the nine months ended September 30, 2016 . Goodwill by segment is as follows for both September 30, 2016 and December 31, 2015 (in thousands): Electric $ 243,558 Natural gas 114,028 Total $ 357,586 |
Comprehensive Income (Loss)
Comprehensive Income (Loss) | 9 Months Ended |
Sep. 30, 2016 | |
Statement of Comprehensive Income [Abstract] | |
Comprehensive Income (Loss) Note [Text Block] | Comprehensive Loss The following tables display the components of Other Comprehensive Loss (in thousands): Three Months Ended September 30, 2016 September 30, 2015 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Foreign currency translation adjustment $ 26 $ — $ 26 $ 233 $ — $ 233 Reclassification of net gains on derivative instruments (2,448 ) 942 (1,506 ) (901 ) 346 (555 ) Other comprehensive loss $ (2,422 ) $ 942 $ (1,480 ) $ (668 ) $ 346 $ (322 ) Nine Months Ended September 30, 2016 September 30, 2015 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Foreign currency translation adjustment $ (84 ) $ — $ (84 ) $ 445 $ — $ 445 Reclassification of net gains on derivative instruments (2,324 ) 892 (1,432 ) (1,187 ) 452 (735 ) Other comprehensive loss $ (2,408 ) $ 892 $ (1,516 ) $ (742 ) $ 452 $ (290 ) Balances by classification included within accumulated other comprehensive loss (AOCL) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands): September 30, 2016 December 31, 2015 Foreign currency translation $ 1,271 $ 1,355 Derivative instruments designated as cash flow hedges (10,446 ) (9,014 ) Pension and postretirement medical plans (937 ) (937 ) Accumulated other comprehensive loss $ (10,112 ) $ (8,596 ) The following tables display the changes in AOCL by component, net of tax (in thousands): Three Months Ended September 30, 2016 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,940 ) $ (937 ) $ 1,245 (8,632 ) Other comprehensive income before reclassifications — — 26 26 Amounts reclassified from AOCL Interest Expense (1,506 ) — — (1,506 ) Net current-period other comprehensive (loss) income (1,506 ) — 26 (1,480 ) Ending balance $ (10,446 ) $ (937 ) $ 1,271 $ (10,112 ) Three Months Ended September 30, 2015 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,496 ) $ (1,247 ) $ 1,009 (8,734 ) Other comprehensive loss before reclassifications — — 233 233 Amounts reclassified from Accumulated Other Comprehensive Income (AOCI) Interest Expense (555 ) — — (555 ) Net current-period other comprehensive (loss) income (555 ) — 233 (322 ) Ending balance $ (9,051 ) $ (1,247 ) $ 1,242 $ (9,056 ) Nine Months Ended September 30, 2016 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,014 ) $ (937 ) $ 1,355 (8,596 ) Other comprehensive loss before reclassifications — — (84 ) (84 ) Amounts reclassified from AOCL Interest Expense (1,432 ) — — (1,432 ) Net current-period other comprehensive loss (1,432 ) — (84 ) (1,516 ) Ending balance $ (10,446 ) $ (937 ) $ 1,271 $ (10,112 ) Nine Months Ended September 30, 2015 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,316 ) $ (1,247 ) $ 797 (8,766 ) Other comprehensive income before reclassifications — — 445 445 Amounts reclassified from AOCI Interest Expense (735 ) — — (735 ) Net current-period other comprehensive (loss) income (735 ) — 445 (290 ) Ending balance $ (9,051 ) $ (1,247 ) $ 1,242 $ (9,056 ) |
Risk Management and Hedging Act
Risk Management and Hedging Activities | 9 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities Disclosure [Text Block] | Risk Management and Hedging Activities Nature of Our Business and Associated Risks We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a portion of our electric and natural gas supply requirements. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations. Objectives and Strategies for Using Derivatives To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. These commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt. Accounting for Derivative Instruments We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Normal Purchases and Normal Sales We have applied the normal purchase and normal sale scope exception (NPNS) to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no unrealized amounts recorded in the Financial Statements at September 30, 2016 and December 31, 2015 . Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered. Credit Risk Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry. Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions. Interest Rate Swaps Designated as Cash Flow Hedges We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCL. We reclassify these gains from AOCL into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands): Location of amount reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Nine Months Ended September 30, 2016 Interest rate contracts Interest Expense $ 2,324 A pre-tax loss of approximately $17.2 million is remaining in AOCL as of September 30, 2016 , and we expect to reclassify approximately $0.6 million of pre-tax losses from AOCL into interest expense during the next twelve months. These amounts relate to terminated swaps. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Disclosures [Text Block] | Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows: • Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities; • Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and • Level 3 – Significant inputs that are generally not observable from market activity. We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 7 - Risk Management and Hedging Activities for further discussion. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Margin Cash Collateral Offset Total Net Fair Value (in thousands) September 30, 2016 Restricted cash $ 6,350 $ — $ — $ — $ 6,350 Rabbi trust investments 25,057 — — — 25,057 Total $ 31,407 $ — $ — $ — $ 31,407 December 31, 2015 Restricted cash $ 6,240 $ — $ — $ — $ 6,240 Rabbi trust investments 24,245 — — — 24,245 Total $ 30,485 $ — $ — $ — $ 30,485 Restricted cash represents amounts held in money market mutual funds. Rabbi trust investments represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets. Financial Instruments The estimated fair value of financial instruments is summarized as follows (in thousands): September 30, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 1,794,519 $ 1,950,837 $ 1,768,183 $ 1,844,974 Short-term borrowings consist of commercial paper and are not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange. We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy. |
Financing Activities
Financing Activities | 9 Months Ended |
Sep. 30, 2016 | |
Financing Activities [Abstract] | |
Long Term Debt [Text Block] | Financing Activities In June 2016, we issued $60 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.80% maturing in 2026 . Proceeds were used to redeem our 6.05% , $55 million South Dakota First Mortgage Bonds due 2018 . In addition, in September 2016, we issued $45.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026 . Proceeds from this issuance were used for general corporate purposes. Both series of these bonds are secured by our electric and natural gas assets in South Dakota, Nebraska, North Dakota, and Iowa and were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. In August 2016, the City of Forsyth, Rosebud County, Montana issued $144.7 million aggregate principal amount of Pollution Control Revenue Refunding Bonds on our behalf. The bonds were issued at a fixed interest rate of 2.00% maturing in 2023 . The proceeds of the issuance were loaned to us pursuant to a Loan Agreement and have been used to partially fund the redemption of the 4.65% , $170.2 million City of Forsyth Pollution Control Revenue Refunding Bonds due 2023 (Prior Bonds) issued on our behalf. We paid the remaining portion of the Prior Bonds with available funds. Our obligation under the Loan Agreement is secured by the issuance of $144.7 million of Montana First Mortgage Bonds. These bonds are secured by our electric and natural gas assets in Montana and Wyoming. The City of Forsyth bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2016 | |
Segment Reporting Information [Line Items] | |
Segment Reporting Disclosure [Text Block] | Segment Information Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which primarily consists of unallocated corporate costs. We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments are as follows (in thousands): Three Months Ended September 30, 2016 Electric Gas Other Eliminations Total Operating revenues 266,629 $ 34,369 $ — $ — $ 300,998 Cost of sales 89,681 6,475 — — 96,156 Gross margin 176,948 27,894 — — 204,842 Operating, general and administrative 50,460 19,141 (1,311 ) — 68,290 Property and other taxes 32,343 8,328 2 — 40,673 Depreciation and depletion 32,549 7,206 8 — 39,763 Operating income (loss) 61,596 (6,781 ) 1,301 — 56,116 Interest expense (19,099 ) (1,249 ) (701 ) — (21,049 ) Other income (loss) 982 345 (1,448 ) — (121 ) Income tax benefit 7,946 1,169 544 — 9,659 Net income (loss) $ 51,425 $ (6,516 ) $ (304 ) $ — $ 44,605 Total assets $ 4,294,549 $ 1,093,333 $ 6,059 — $ 5,393,941 Capital expenditures $ 66,322 $ 16,430 $ — — $ 82,752 Three Months Ended September 30, 2015 Electric Gas Other Eliminations Total Operating revenues $ 238,513 $ 34,226 $ — $ — $ 272,739 Cost of sales 66,197 7,380 — — 73,577 Gross margin 172,316 26,846 — — 199,162 Operating, general and administrative 58,298 19,843 1,155 — 79,296 Property and other taxes 28,648 7,062 2 — 35,712 Depreciation and depletion 28,476 7,209 8 — 35,693 Operating income (loss) 56,894 (7,268 ) (1,165 ) — 48,461 Interest expense (19,078 ) (2,562 ) (403 ) — (22,043 ) Other income 1,832 507 1,430 — 3,769 Income tax (expense) benefit (6,553 ) 1,883 (1,719 ) — (6,389 ) Net income (loss) $ 33,095 $ (7,440 ) $ (1,857 ) $ — $ 23,798 Total assets $ 4,169,423 $ 1,057,919 $ 7,736 $ — $ 5,235,078 Capital expenditures $ 57,813 $ 14,341 $ — $ — $ 72,154 Nine Months Ended September 30, 2016 Electric Gas Other Eliminations Total Operating revenues $ 756,374 $ 170,283 $ — $ — $ 926,657 Cost of sales 245,470 47,813 — — 293,283 Gross margin 510,904 122,470 — — 633,374 Operating, general and administrative 157,471 61,638 1,621 — 220,730 Property and other taxes 87,094 24,200 8 — 111,302 Depreciation and depletion 97,614 21,913 24 — 119,551 Operating income (loss) 168,725 14,719 (1,653 ) — 181,791 Interest expense (65,273 ) (5,018 ) (1,688 ) — (71,979 ) Other income 2,136 925 1,115 — 4,176 Income tax benefit (expense) 3,600 (574 ) 1,214 — 4,240 Net income (loss) $ 109,188 $ 10,052 $ (1,012 ) $ — $ 118,228 Total assets $ 4,294,549 $ 1,093,333 $ 6,059 — $ 5,393,941 Capital expenditures $ 165,885 $ 38,113 $ — — $ 203,998 Nine Months Ended September 30, 2015 Electric Gas Other Eliminations Total Operating revenues $ 695,921 $ 193,389 $ — $ — $ 889,310 Cost of sales 196,034 69,461 — — 265,495 Gross margin 499,887 123,928 — — 623,815 Operating, general and administrative 179,191 63,554 (20,606 ) — 222,139 Property and other taxes 78,987 21,958 8 — 100,953 Depreciation and depletion 85,523 21,691 25 — 107,239 Operating income 156,186 16,725 20,573 — 193,484 Interest expense (58,524 ) (8,304 ) (1,273 ) — (68,101 ) Other income (expense) 4,773 1,349 (693 ) — 5,429 Income tax expense (16,364 ) (1,621 ) (6,631 ) — (24,616 ) Net income $ 86,071 $ 8,149 $ 11,976 $ — $ 106,196 Total assets $ 4,169,423 1,057,919 $ 7,736 $ — $ 5,235,078 Capital expenditures $ 171,800 31,524 $ — $ — $ 203,324 |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 30, 2016 | |
Earnings Per Share [Abstract] | |
Earnings Per Share [Text Block] | Earnings Per Share Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows: Three Months Ended September 30, 2016 September 30, 2015 Basic computation 48,314,783 47,065,082 Dilutive effect of: Performance share awards (1) 154,537 245,463 Diluted computation 48,469,320 47,310,545 Nine Months Ended September 30, 2016 September 30, 2015 Basic computation 48,288,678 47,028,924 Dilutive effect of: Performance share awards (1) 154,889 245,460 Diluted computation 48,443,567 47,274,384 ______________ (1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award. |
Employee Benefit Plans
Employee Benefit Plans | 9 Months Ended |
Sep. 30, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Pension and Other Postretirement Benefits Disclosure [Text Block] | Employee Benefit Plans Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands): Pension Benefits Other Postretirement Benefits Three Months Ended Three Months Ended 2016 2015 2016 2015 Components of Net Periodic Benefit Cost (Income) Service cost $ 2,939 $ 3,091 $ 123 $ 132 Interest cost 6,553 6,544 198 197 Expected return on plan assets (7,062 ) (7,890 ) (261 ) (242 ) Amortization of prior service cost 62 62 (471 ) (471 ) Recognized actuarial loss 2,472 2,659 78 96 Net Periodic Benefit Cost (Income) $ 4,964 $ 4,466 $ (333 ) $ (288 ) Pension Benefits Other Postretirement Benefits Nine Months Ended Nine Months Ended 2016 2015 2016 2015 Components of Net Periodic Benefit Cost (Income) Service cost 8,819 $ 9,272 $ 369 $ 395 Interest cost 19,658 19,631 596 590 Expected return on plan assets (21,186 ) (23,671 ) (782 ) (727 ) Amortization of prior service cost 185 185 (1,412 ) (1,412 ) Recognized actuarial loss 7,416 7,976 236 289 Net Periodic Benefit Cost (Income) $ 14,892 $ 13,393 $ (993 ) $ (865 ) |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies Disclosure [Text Block] | Commitments and Contingencies ENVIRONMENTAL LIABILITIES AND REGULATION Environmental Matters The operation of electric generating, transmission and distribution facilities, and gas gathering, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, the majority of our environmental reserve relates to the remediation of former manufactured gas plant sites owned by us and is estimated to range between $27 million to $32 million . As of September 30, 2016 , we have a reserve of approximately $30.3 million , which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred. Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations. Manufactured Gas Plants - Approximately $23.7 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of September 30, 2016 , the reserve for remediation costs at this site is approximately $11.1 million , and we estimate that approximately $6.5 million of this amount will be incurred during the next five years. We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations. In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana's state superfund list, were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. In August 2016, the MDEQ sent us a letter of Notice of Potential Liability and Request for Remedial Action regarding the Helena site. An initial scoping meeting with MDEQ regarding this letter has not yet been scheduled. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte and Helena sites. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. Monitoring wells have been installed and groundwater is monitored semiannually. At the request of Missoula Valley Water Quality District (MVWQD), a draft risk assessment was prepared for the Missoula site and presented to the MVWQD. We and the MVWQD agreed additional site investigation work is appropriate. The additional investigation work began in December 2015 and has continued in 2016. The result of the additional investigation work may lead to the development of site-specific risk-based remedial alternatives report followed by implementation of a remedy. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site. Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide (CO 2 ). These actions include legislative proposals, Executive and Environmental Protection Agency (EPA) actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of GHG emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. While numerous bills have been introduced that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating new and existing sources of GHG emissions. On August 3, 2015, the EPA released for publication in the Federal Register, the final standards of performance to limit GHG emissions from new, modified and reconstructed fossil fuel generating units and from newly constructed and reconstructed natural gas combined cycle (NGCC) units. The standards reflect the degree of emission limitations achievable through the application of the best system of emission reduction that the EPA determined has been demonstrated for each type of unit. In a separate action that also affects power plants, on August 3, 2015, the EPA released its final rule establishing GHG performance standards for existing power plants under Clean Air Act Section 111(d) (the Clean Power Plan, or CPP). The CPP establishes CO 2 emission performance standards for existing electric utility steam generating units and NGCC units. States may develop implementation plans for affected units to meet the individual state targets established in the CPP or may adopt a federal plan. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour (MWH)) or mass-based tonnage limits for CO 2 . The 2030 rate-based requirement for all existing affected generating units in South Dakota and Montana is 1,167 and 1,305 pounds per MWH, respectively. The rate-based approach requires a 38.4 percent reduction in South Dakota and a 47.4 percent reduction in Montana from 2012 levels by 2030. The mass-based approach for existing units in South Dakota requires a 30.9 percent decrease by 2030, while in Montana the mass-based approach requires a 41 percent decrease by 2030. States were required to submit initial plans for achieving GHG emission standards to EPA by September 2016, and could seek additional time to finalize State plans by September 2018. Due to the stay of the rule, discussed below, South Dakota and Montana have not submitted implementation plans. The initial performance period for compliance under the CPP would commence in 2022, with full implementation by 2030. The EPA also indicated that states may establish emission trading programs to facilitate compliance with the CPP and provides three options: an emission rate trading program that would allow the trading of emission reduction credits equal to one MWH of emission free generation; a mass-based program that would allow trading of allowances with an allowance equal to one short ton of CO 2 ; and a state measures program that would allow intra-state trading to achieve the state-wide average emission rate. On August 3, 2015, the EPA also proposed a federal plan that would be imposed if a state fails to submit a satisfactory plan under the CPP. The federal plan proposal includes a "model trading rule" that describes how the EPA would establish an emission trading program as part of the federal plan to allow affected units to comply with the emission rate requirements. EPA proposed both an emission rate trading plan and a mass-based trading plan and indicated that the final federal rule will elect one of the two options. The CPP reduction of 47.4 percent in carbon dioxide emissions in Montana by 2030 is the greatest reduction target among the lower 48 states, according to a nationwide analysis. Our Montana generation portfolio emits less carbon on average than the EPA's 2030 target due to investments we made prior to 2013 in carbon-free generation resources. However, under the CPP, investments made in renewable energy prior to 2012 are not counted for compliance with the CPP's requirements. We asked the University of Montana’s Bureau of Business and Economic Research (BBER) to study the potential impacts of the CPP across Montana. The BBER study looked at the implications of closing all four of the generating units that comprise the Colstrip facility in southeast Montana as a scenario for complying with the federal rule. The study's conclusions describe the likely loss of jobs and population, the decline in the local and state tax base, the impact on businesses statewide, and the closure's impact on electric reliability and affordability. The electricity produced at Colstrip Unit 4 represents approximately 25 percent of our customer needs. Closing all four Colstrip units would lead to higher utility rates in order to replace the base-load generation that currently is provided by Colstrip. Closing all four Colstrip units would also create significant issues with the transmission grid that serves Montana, and we would lose transmission revenues that are credited to and lower electric customer bills. On October 23, 2015, the same date the CPP was published in the Federal Register, we along with other utilities, trade groups, coal producers, and labor and business organizations, filed Petitions for Review of the CPP with the United States Court of Appeals for the District of Columbia Circuit. Accompanying these Petitions for Review were Motions to Stay the implementation of the CPP. On January 21, 2016, the U.S. Court of Appeals for the District of Columbia denied the requests for stay but ordered expedited briefing on the merits. On January 26, 2016, 29 states and state agencies asked the U.S. Supreme Court to issue an immediate stay of the CPP. On January 27, 2016, 60 utilities and allied petitioners also requested the U.S. Supreme Court to immediately stay the CPP, and we were among the utilities seeking a stay. On February 9, 2016, the U.S. Supreme Court entered an order staying the CPP. The stay of the CPP will remain in place until the U.S. Supreme Court either denies a petition for certiorari following the U.S. Court of Appeals’ decision on the substantive challenges to the CPP, if one is submitted, or until the U.S. Supreme Court enters judgment following grant of a petition for certiorari. On May 16, 2016, the U.S. Court of Appeals for the District of Columbia entered an order declaring the challenge to the CPP would be reviewed en banc, and on September 27, 2016, the Court held oral argument in the matter. An initial ruling on the challenge is not expected until early 2017, and the U.S. Supreme Court decision on challenges to the CPP is not anticipated until mid-2017, if not early 2018. On December 22, 2015 we also filed an administrative Petition for Reconsideration with the EPA, requesting that it reconsider the CPP, on the grounds that the CO 2 reductions in the CPP were substantially greater in Montana than in the proposed rule. We also requested EPA stay the CPP while it considered our Petition for Reconsideration. At this time, the EPA has taken no action on the Petition for Reconsideration or stay request. On June 23, 2014, the U.S. Supreme Court struck down the EPA's Tailoring Rule, which limited the sources subject to GHG permitting requirements to the largest fossil-fueled power plants, indicating that EPA had exceeded its authority under the Clean Air Act by "rewriting unambiguous statutory terms." However, the decision affirmed EPA's ability to regulate GHG emissions from sources already subject to regulation under the prevention of significant deterioration program, which includes most electric generating units. Requirements to reduce GHG emissions could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Although there continues to be proposed legislation and regulations that affect GHG emissions from power plants, technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. In addition, physical impacts of climate change may present potential risks for severe weather, such as droughts, floods and tornadoes, in the locations where we operate or have interests. We are evaluating the implications of these rules and technology available to achieve the CO 2 emission performance standards. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the final rules that, in our view, disproportionately impact customers in our region, and to seek relief from the final compliance requirements. We cannot predict the ultimate outcome of these matters or what our obligations might be under the state compliance plans with any degree of certainty until they are finalized; however, complying with the carbon emission standards, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources. Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best technology available (BTA)” for minimizing environmental impacts. In May 2014, the EPA issued a final rule applicable to facilities that withdraw at least 2 million gallons per day of cooling water from waters of the US and use at least 25 percent of the water exclusively for cooling purposes. The final rule, which became effective in October 2014, gives options for meeting BTA, and provides a flexible compliance approach. Under the rule, permits required for existing facilities will be developed by the individual states and additional capital and/or increased operating costs may be required to comply with future water permit requirements. Challenges to the final cooling water intake rule filed by industry and environmental groups are under review in the Second Circuit Court of Appeals. In November 2015, the EPA published final regulations on effluent limitations for power plant wastewater discharges, including mercury, arsenic, lead and selenium. The rule became effective in January 2016. Some of the new requirements for existing power plants would be phased in starting in 2018 with full implementation of the rule by 2023. The EPA rule estimates that 12 percent of the steam electric power plants in the U.S. will have to make new investments to meet the requirements of the new effluent limitation regulations. Challenges to the final rule have been filed in the Fifth Circuit Court of Appeals, indicating that the EPA underestimated compliance costs. It is too early to determine whether the impacts of these rules will be material. Clean Air Act Rules and Associated Emission Control Equipment Expenditures - The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants in which we have joint ownership. In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS). Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. The rule was challenged by industry groups and states, and was upheld by the D.C. Circuit Court in April 2014. The decision was appealed to the Supreme Court and in June 2015, the Supreme Court issued an opinion that the EPA did not properly consider the costs to industry when making the requisite “appropriate and necessary” determination as part of its analysis in connection with the issuance of the MATS rule. The Supreme Court remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit, and the D.C. Circuit remanded, without vacatur, the MATS rule to the EPA, leaving the rule in place. In April 2016, the EPA published its final supplemental finding that it is "appropriate and necessary" to regulate coal and oil-fired units under Section 112 of the Clean Air Act. Although industry and trade associations have filed a lawsuit in the D.C. Circuit challenging the EPA's supplemental finding, installation or upgrading of relevant environmental controls at our affected plants is complete and we are controlling emissions of mercury under the state and Federal MATS rules. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under CSAPR, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide (SO 2 ) were to be required in certain states beginning in 2012. In April 2014 the Supreme Court reversed and remanded the 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated the CSAPR. In December, 2015 EPA published a proposed update to the CSAPR rule. Litigation of the remaining CSAPR lawsuits is pending. In October 2013, the Supreme Court denied certiorari in Luminant Generation Co v. EPA , which challenged the EPA’s current approach to regulating air emissions during startup, shutdown and malfunction (SSM) events. As a result, fossil fuel power plants may need to address SSM in their permits to reduce the risk of enforcement or citizen actions. The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in 'Class I' areas. In September 2012, a final Federal Implementation Plan for Montana was published in the Federal Register to address regional haze. As finalized, Colstrip Units 3 and 4 do not have to improve removal efficiency for pollutants that contribute to regional haze. By 2018, Montana, or EPA, must develop a revised plan that demonstrates reasonable progress toward eliminating man made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. In November 2012, PPL Montana (now Talen Montana), the operator of Colstrip, as well as environmental groups (National Parks Conservation Association, Montana Environmental Information Center (MEIC), and Sierra Club) jointly filed a petition for review of the Federal Implementation Plan in the U.S. Court of Appeals for the Ninth Circuit. MEIC and Sierra Club challenged the EPA's decision not to require any emissions reductions from Colstrip Units 3 and 4. In June 2015, the U.S. Court of Appeals for the Ninth Circuit rejected the challengers’ contention that the EPA should have required additional pollution-reduction technologies on Unit 4 beyond those in the regulations and the matter is back in EPA Region 8 for action. Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to the various regulations discussed above that have been issued or proposed. Each state is required by the CPP to submit a satisfactory plan to EPA by September 2018. The state plans will determine whether we will have to meet rate-based or mass-based requirements and, if the state adopts a mass-based plan, the number of vintages of allowances that will be allocated to our facilities. Until the plans are submitted, or a federal plan is imposed, we cannot predict the impact of the CPP on us. In addition, compliance with the final rule on Water Intakes and Discharges discussed above, which became effective in January 2016, did not have a significant impact at any of our jointly owned facilities. North Dakota . The North Dakota Regional Haze SIP requires the Coyote generating facility, in which we have 10% ownership, to reduce its NOx emissions by July 2018. In 2016, Coyote completed installation of control equipment to maintain compliance with the lower NOx emissions of 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown. The cost of the control equipment was not significant. Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is subject to EPA's coal combustion residual rule. A compliance plan has been developed and is in the initial stages of implementation. The current estimate of the total project cost is approximately $90.0 million (our share is 30% ) over the remaining life of the facility. See 'Legal Proceedings - Colstrip Litigation' below for discussion of Sierra Club litigation. Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment. We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties: • We may not know all sites for which we are alleged or will be found to be responsible for remediation; and • Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation. LEGAL PROCEEDINGS Colstrip Litigation On March 6, 2013, the Sierra Club and the MEIC (Plaintiffs) filed suit in the United States District Court for the District of Montana (Court) against the six individual owners of the Colstrip Generating Station (Colstrip), including us, as well as Talen Montana (Talen), the operator or managing agent of the station. Colstrip consists of four coal fired generating units. Colstrip Units 1 and 2 are older than Units 3 and 4. We do not have an ownership interest in Units 1 and 2. We have a 30 percent joint interest in Unit 4 and a reciprocal sharing agreement with Talen regarding the operation of Colstrip Units 3 and 4, in which each party receives 15% of the respective combined output of the units and is responsible for 15 percent of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or Unit 4. On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief that dropped claims associated with projects completed before 2001, Title V claims and the opacity claims. The Amended Complaint alleged a total of 23 claims covering 64 projects. In the Amended Complaint, Plaintiffs identified physical changes made at Colstrip between 2001 and 2012, that Plaintiffs allege (a) have increased emissions of SO 2 , NOx and particulate matter and (b) were “major modifications” subject to permitting requirements under the Clean Air Act. They also alleged violations of the requirements related to Part 70 Operating Permits. In 2013, the Colstrip owners and operator filed partial motions to dismiss. On September 12, 2013, Plaintiffs filed a motion for partial summary judgment as to the applicable method for calculating emissions increases from modifications. The parties filed a joint notice (Notice) on April 21, 2014, that advised the Court of Plaintiffs’ intent to file a Second Amended Complaint which dropped claims relating to 52 projects, and added one additional project. On May 6, 2014, the Court held oral argument on Defendants' motion to dismiss and on Plaintiffs’ motion for summary judgment on the applicable legal standard. On May 22, 2014, the United States Magistrate Judge (Magistrate) issued findings and recommendations, which denied Plaintiffs’ motion for summary judgment and denied most of the Colstrip owners’ motions to dismiss, but dismissed seven of Plaintiffs’ “best available control technology” claims and dismissed two of Plaintiffs' claims for injunctive relief. The Plaintiffs filed an objection to the Magistrate's findings and recommendations with the Court, and on August 13, 2014, the Court adopted the Magistrate's findings and conclusions. On August 27, 2014, the Plaintiffs filed their Second Amended Complaint, which alleged a total of 13 claims covering eight projects and seeks injunctive and declaratory relief, civil penalties (including $100,000 of civil penalties to be used for beneficial environmental projects), and recovery of their attorney fees. Defendants filed their Answer to the Second Amended Complaint on September 26, 2014. After filing the Second Amended Complaint, Plaintiffs indicated that they were no longer pursuing a number of claims and projects thereby reducing their total to eight claims relating to four projects. The parties filed motions for summary judgment and briefs in support with regard to issues affecting the remaining claims. On December 1, 2015, the Court held oral argument on all pending motions for summary judgment, and on December 31, 2015, the Magistrate issued findings and recommendations which (a) denied Plaintiffs’ motion for partial summary judgment regarding routine maintenance, repair and replacement; (b) denied Plaintiffs’ motion for partial summary judgment that the redesign projects for the Unit 1 and 4 turbines and the Unit 1 economizer were not “like kind replacements”; (c) granted Defendants’ motion for partial summary judgment regarding Plaintiffs’ use of the “actual-to-potential” emissions test; (d) granted in part and denied in part Plaintiffs’ motion for partial summary judgment regarding the allowable period from which to select a baseline for the Unit 3 reheater project; (e) granted in part and denied in part Defendants’ motion for partial summary judgment on baseline selection; and (f) granted Defendants’ motion for partial summary judgment on emissions calculations for alleged aggregated turbine and safety valve project. With the matter scheduled to go to a bench trial, on April 26, 2016, the parties filed a joint motion to vacate the May 31, 2016, trial date and to stay all deadlines, to allow the parties to settle the litigation. On July 12, 2016, the parties lodged a proposed consent decree with the Court. The Court entered the consent decree on September 6, 2016, dismissing all of the claims against all units, including Colstrip Unit 4, the only unit in which we have an ownership interest. While the consent decree does not provide a shut-down date for Units 3 and 4, it does provide that Units 1 and 2 must be shut down by July 1, 2022. Units 1 and 2 are owned solely by Talen and Puget Sound Energy. We had no role in the decisions regarding Units 1 and 2 as we have no ownership interest in those units. With the anticipated shutdown of Units 1 and 2, we anticipate incurring incremental operating costs with respect to our interest in Unit 4. We do not anticipate that this increase will have a significant impact on our results of operations or cash flows. However, the ultimate shutdown of Talen's share of Colstrip Units 1 and 2 will have a negative impact on our transmission revenue due to less energy available to transmit across our transmission lines. The consent decree gave the Plaintiffs and Defendants each the right to seek recovery of attorneys’ fees and costs from the other party by filing a motion with the Court by October 6, 2016. Each party filed such a motion on a timely basis. While we cannot predict an outcome on the opposing motions seeking attorneys’ fees and costs, we do not anticipate that the outcome will have a significant impact on our results of operations or cash flows. Billings, Montana Refinery Outage Claim In August 2014, we received a letter from the ExxonMobil refinery in Billings claiming that it had sustained approximately $48.5 million in damages as a result of a January 2014 electrical outage. In December 2015, ExxonMobil increased the estimated losses related to that incident to approximately $61.7 million . On January 13, 2016, a second electrical outage shut down the ExxonMobil refinery. On January 22, 2016, ExxonMobil filed suit against NorthWestern in U.S. District Court in Billings, Montana, seeking unspecified compensatory and punitive damages arising from both outages. ExxonMobil currently claims property damages and economic losses of at least $65.6 million . We dispute ExxonMobil’s claims and intend to vigorously defend this lawsuit. We have reported the refinery's claims and lawsuit to our liability insurance carriers under our liability insurance coverage, which has a $2.0 million per occurrence retention. We also have brought third-party complaints against the City of Billings and General Electric International, Inc. alleging that they are responsible in whole or in part for the outages. This matter is in the initial stages and we cannot predict an outcome or estimate the amount or range of loss that would be associated with an adverse result. State of Montana - Riverbed Rents On April 1, 2016, the State of Montana filed a complaint on remand with the Montana First Judicial District Court (State District Court), naming us, along with Talen, as defendants. The State claims it owns the riverbeds underlying 10 of our hydroelectric facilities (dams, al |
Nature of Operations and Basi21
Nature of Operations and Basis of Consolidation (Policies) | 9 Months Ended |
Sep. 30, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Consolidation, Variable Interest Entity [Policy Text Block] | Variable Interest Entities A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain Qualifying Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $252.9 million through 2024 . |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands): Three Months Ended 2016 2015 Income Before Income Taxes $ 34,946 $ 30,187 Income tax calculated at 35% federal statutory rate 12,231 35.0 % 10,565 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (615 ) (1.8 ) (857 ) (2.8 ) Flow-through repairs deductions (18,995 ) (54.4 ) (2,779 ) (9.2 ) Production tax credits (2,218 ) (6.3 ) (733 ) (2.4 ) Plant and depreciation of flow through items (243 ) (0.7 ) (374 ) (1.2 ) Prior year permanent return to accrual adjustments — — 1,025 3.4 Other, net 181 0.6 (458 ) (1.6 ) (21,890 ) (62.6 ) (4,176 ) (13.8 ) $ (9,659 ) (27.6 )% $ 6,389 21.2 % Nine Months Ended 2016 2015 Income Before Income Taxes $ 113,988 $ 130,812 Income tax calculated at 35% federal statutory rate 39,896 35.0 % 45,784 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (2,740 ) (2.4 ) (329 ) (0.3 ) Flow-through repairs deductions (32,640 ) (28.6 ) (17,240 ) (13.2 ) Production tax credits (7,317 ) (6.4 ) (2,645 ) (2.0 ) Plant and depreciation of flow through items (1,427 ) (1.3 ) (1,000 ) (0.8 ) Prior year permanent return to accrual adjustments (128 ) (0.1 ) 1,025 0.8 Other, net 116 0.1 (979 ) (0.7 ) (44,136 ) (38.7 ) (21,168 ) (16.2 ) $ (4,240 ) (3.7 )% $ 24,616 18.8 % |
Goodwill (Tables)
Goodwill (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Goodwill [Abstract] | |
Schedule of Goodwill [Table Text Block] | Goodwill by segment is as follows for both September 30, 2016 and December 31, 2015 (in thousands): Electric $ 243,558 Natural gas 114,028 Total $ 357,586 |
Comprehensive Income (Loss) Com
Comprehensive Income (Loss) Comprehensive Income Loss (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Equity [Abstract] | |
Comprehensive Income (Loss) [Table Text Block] | The following tables display the components of Other Comprehensive Loss (in thousands): Three Months Ended September 30, 2016 September 30, 2015 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Foreign currency translation adjustment $ 26 $ — $ 26 $ 233 $ — $ 233 Reclassification of net gains on derivative instruments (2,448 ) 942 (1,506 ) (901 ) 346 (555 ) Other comprehensive loss $ (2,422 ) $ 942 $ (1,480 ) $ (668 ) $ 346 $ (322 ) Nine Months Ended September 30, 2016 September 30, 2015 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Foreign currency translation adjustment $ (84 ) $ — $ (84 ) $ 445 $ — $ 445 Reclassification of net gains on derivative instruments (2,324 ) 892 (1,432 ) (1,187 ) 452 (735 ) Other comprehensive loss $ (2,408 ) $ 892 $ (1,516 ) $ (742 ) $ 452 $ (290 ) |
Comprehensive Income (Loss) Cla
Comprehensive Income (Loss) Classification Accumulated Other Comprehensive (Income) Loss (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Statement of Financial Position [Abstract] | |
Accumulated Other Comprehensive Income [Table Text Block] | Balances by classification included within accumulated other comprehensive loss (AOCL) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands): September 30, 2016 December 31, 2015 Foreign currency translation $ 1,271 $ 1,355 Derivative instruments designated as cash flow hedges (10,446 ) (9,014 ) Pension and postretirement medical plans (937 ) (937 ) Accumulated other comprehensive loss $ (10,112 ) $ (8,596 ) |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The following tables display the changes in AOCL by component, net of tax (in thousands): Three Months Ended September 30, 2016 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,940 ) $ (937 ) $ 1,245 (8,632 ) Other comprehensive income before reclassifications — — 26 26 Amounts reclassified from AOCL Interest Expense (1,506 ) — — (1,506 ) Net current-period other comprehensive (loss) income (1,506 ) — 26 (1,480 ) Ending balance $ (10,446 ) $ (937 ) $ 1,271 $ (10,112 ) Three Months Ended September 30, 2015 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,496 ) $ (1,247 ) $ 1,009 (8,734 ) Other comprehensive loss before reclassifications — — 233 233 Amounts reclassified from Accumulated Other Comprehensive Income (AOCI) Interest Expense (555 ) — — (555 ) Net current-period other comprehensive (loss) income (555 ) — 233 (322 ) Ending balance $ (9,051 ) $ (1,247 ) $ 1,242 $ (9,056 ) Nine Months Ended September 30, 2016 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,014 ) $ (937 ) $ 1,355 (8,596 ) Other comprehensive loss before reclassifications — — (84 ) (84 ) Amounts reclassified from AOCL Interest Expense (1,432 ) — — (1,432 ) Net current-period other comprehensive loss (1,432 ) — (84 ) (1,516 ) Ending balance $ (10,446 ) $ (937 ) $ 1,271 $ (10,112 ) Nine Months Ended September 30, 2015 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,316 ) $ (1,247 ) $ 797 (8,766 ) Other comprehensive income before reclassifications — — 445 445 Amounts reclassified from AOCI Interest Expense (735 ) — — (735 ) Net current-period other comprehensive (loss) income (735 ) — 445 (290 ) Ending balance $ (9,051 ) $ (1,247 ) $ 1,242 $ (9,056 ) |
Risk Management and Hedging A26
Risk Management and Hedging Activities (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands): Location of amount reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Nine Months Ended September 30, 2016 Interest rate contracts Interest Expense $ 2,324 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 7 - Risk Management and Hedging Activities for further discussion. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Margin Cash Collateral Offset Total Net Fair Value (in thousands) September 30, 2016 Restricted cash $ 6,350 $ — $ — $ — $ 6,350 Rabbi trust investments 25,057 — — — 25,057 Total $ 31,407 $ — $ — $ — $ 31,407 December 31, 2015 Restricted cash $ 6,240 $ — $ — $ — $ 6,240 Rabbi trust investments 24,245 — — — 24,245 Total $ 30,485 $ — $ — $ — $ 30,485 |
Fair Value Financial Instruments [Table Text Block] | The estimated fair value of financial instruments is summarized as follows (in thousands): September 30, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 1,794,519 $ 1,950,837 $ 1,768,183 $ 1,844,974 |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Financial data for the business segments are as follows (in thousands): Three Months Ended September 30, 2016 Electric Gas Other Eliminations Total Operating revenues 266,629 $ 34,369 $ — $ — $ 300,998 Cost of sales 89,681 6,475 — — 96,156 Gross margin 176,948 27,894 — — 204,842 Operating, general and administrative 50,460 19,141 (1,311 ) — 68,290 Property and other taxes 32,343 8,328 2 — 40,673 Depreciation and depletion 32,549 7,206 8 — 39,763 Operating income (loss) 61,596 (6,781 ) 1,301 — 56,116 Interest expense (19,099 ) (1,249 ) (701 ) — (21,049 ) Other income (loss) 982 345 (1,448 ) — (121 ) Income tax benefit 7,946 1,169 544 — 9,659 Net income (loss) $ 51,425 $ (6,516 ) $ (304 ) $ — $ 44,605 Total assets $ 4,294,549 $ 1,093,333 $ 6,059 — $ 5,393,941 Capital expenditures $ 66,322 $ 16,430 $ — — $ 82,752 Three Months Ended September 30, 2015 Electric Gas Other Eliminations Total Operating revenues $ 238,513 $ 34,226 $ — $ — $ 272,739 Cost of sales 66,197 7,380 — — 73,577 Gross margin 172,316 26,846 — — 199,162 Operating, general and administrative 58,298 19,843 1,155 — 79,296 Property and other taxes 28,648 7,062 2 — 35,712 Depreciation and depletion 28,476 7,209 8 — 35,693 Operating income (loss) 56,894 (7,268 ) (1,165 ) — 48,461 Interest expense (19,078 ) (2,562 ) (403 ) — (22,043 ) Other income 1,832 507 1,430 — 3,769 Income tax (expense) benefit (6,553 ) 1,883 (1,719 ) — (6,389 ) Net income (loss) $ 33,095 $ (7,440 ) $ (1,857 ) $ — $ 23,798 Total assets $ 4,169,423 $ 1,057,919 $ 7,736 $ — $ 5,235,078 Capital expenditures $ 57,813 $ 14,341 $ — $ — $ 72,154 Nine Months Ended September 30, 2016 Electric Gas Other Eliminations Total Operating revenues $ 756,374 $ 170,283 $ — $ — $ 926,657 Cost of sales 245,470 47,813 — — 293,283 Gross margin 510,904 122,470 — — 633,374 Operating, general and administrative 157,471 61,638 1,621 — 220,730 Property and other taxes 87,094 24,200 8 — 111,302 Depreciation and depletion 97,614 21,913 24 — 119,551 Operating income (loss) 168,725 14,719 (1,653 ) — 181,791 Interest expense (65,273 ) (5,018 ) (1,688 ) — (71,979 ) Other income 2,136 925 1,115 — 4,176 Income tax benefit (expense) 3,600 (574 ) 1,214 — 4,240 Net income (loss) $ 109,188 $ 10,052 $ (1,012 ) $ — $ 118,228 Total assets $ 4,294,549 $ 1,093,333 $ 6,059 — $ 5,393,941 Capital expenditures $ 165,885 $ 38,113 $ — — $ 203,998 Nine Months Ended September 30, 2015 Electric Gas Other Eliminations Total Operating revenues $ 695,921 $ 193,389 $ — $ — $ 889,310 Cost of sales 196,034 69,461 — — 265,495 Gross margin 499,887 123,928 — — 623,815 Operating, general and administrative 179,191 63,554 (20,606 ) — 222,139 Property and other taxes 78,987 21,958 8 — 100,953 Depreciation and depletion 85,523 21,691 25 — 107,239 Operating income 156,186 16,725 20,573 — 193,484 Interest expense (58,524 ) (8,304 ) (1,273 ) — (68,101 ) Other income (expense) 4,773 1,349 (693 ) — 5,429 Income tax expense (16,364 ) (1,621 ) (6,631 ) — (24,616 ) Net income $ 86,071 $ 8,149 $ 11,976 $ — $ 106,196 Total assets $ 4,169,423 1,057,919 $ 7,736 $ — $ 5,235,078 Capital expenditures $ 171,800 31,524 $ — $ — $ 203,324 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Earnings Per Share [Abstract] | |
Schedule of Weighted Average Number of Shares [Table Text Block] | Average shares used in computing the basic and diluted earnings per share are as follows: Three Months Ended September 30, 2016 September 30, 2015 Basic computation 48,314,783 47,065,082 Dilutive effect of: Performance share awards (1) 154,537 245,463 Diluted computation 48,469,320 47,310,545 Nine Months Ended September 30, 2016 September 30, 2015 Basic computation 48,288,678 47,028,924 Dilutive effect of: Performance share awards (1) 154,889 245,460 Diluted computation 48,443,567 47,274,384 ______________ (1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award. |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Schedule of Defined Benefit Plans Disclosures [Table Text Block] | Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands): Pension Benefits Other Postretirement Benefits Three Months Ended Three Months Ended 2016 2015 2016 2015 Components of Net Periodic Benefit Cost (Income) Service cost $ 2,939 $ 3,091 $ 123 $ 132 Interest cost 6,553 6,544 198 197 Expected return on plan assets (7,062 ) (7,890 ) (261 ) (242 ) Amortization of prior service cost 62 62 (471 ) (471 ) Recognized actuarial loss 2,472 2,659 78 96 Net Periodic Benefit Cost (Income) $ 4,964 $ 4,466 $ (333 ) $ (288 ) Pension Benefits Other Postretirement Benefits Nine Months Ended Nine Months Ended 2016 2015 2016 2015 Components of Net Periodic Benefit Cost (Income) Service cost 8,819 $ 9,272 $ 369 $ 395 Interest cost 19,658 19,631 596 590 Expected return on plan assets (21,186 ) (23,671 ) (782 ) (727 ) Amortization of prior service cost 185 185 (1,412 ) (1,412 ) Recognized actuarial loss 7,416 7,976 236 289 Net Periodic Benefit Cost (Income) $ 14,892 $ 13,393 $ (993 ) $ (865 ) |
Nature of Operations and Basi31
Nature of Operations and Basis of Consolidation (Details) $ in Millions | Sep. 30, 2016USD ($)watts | Dec. 31, 2015customers |
Number of customers | customers | 701,000 | |
Number of megawatts of qualifying facility | watts | 35 | |
Estimated aggregate gross contractual payments for qualifying facilities through 2024 | $ | $ 252.9 |
New Accounting Standards Accoun
New Accounting Standards Accounting Standards Adopted (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Accounting Changes and Error Corrections [Abstract] | ||
Debt issuance costs reclassified as adjustments to carrying cost of debt | $ 13.9 | $ 13 |
Regulatory Matters (Details)
Regulatory Matters (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 41 Months Ended | ||
Jun. 30, 2016 | Sep. 30, 2016 | Nov. 30, 2015 | Mar. 31, 2016 | Dec. 31, 2015 | |
Public Utilities, General Disclosures [Line Items] | |||||
Property, plant and equipment, net | $ 4,161,993 | $ 4,059,499 | |||
Montana Natural Gas Rate Filing [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Requested rate increase | 10,900 | ||||
Requested rate increase for delivery service | 7,400 | ||||
Requested rate increase for production | $ 3,500 | ||||
Requested return on equity, percentage | 10.35% | ||||
Public utilities rate base | $ 432,100 | ||||
Requested debt capital structure, percentage | 53.00% | ||||
Requested equity capital structure, percentage | 47.00% | ||||
Interim rate increase | $ 5,600 | ||||
Hydro Transaction [Member] | Revenue Subject to Refund [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Deferred revenue, current | 2,600 | ||||
Demand side management [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Demand side management revenue recognized annually | $ 7,100 | ||||
Deferred revenue recognized | $ 14,200 | ||||
Deferred revenue | $ 14,200 | ||||
Dave Gates Generating Station [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Deferred revenue, refund payments | 27,300 | ||||
Property, plant and equipment, net | 160,000 | ||||
Disallowed Expenses [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Disallowed replacement power costs | $ 8,200 | ||||
Disallowed costs | 12,400 | 10,300 | |||
Disallowed interest costs | $ 2,900 | ||||
Disallowed modeling costs | $ 2,100 | ||||
Disallowed modeling cost reduction | $ 800 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | |
Income Tax Contingency [Line Items] | ||||
Income tax benefit | $ 15.5 | |||
Tax benefit related to prior years | 12.5 | |||
Unrecognized tax benefit more likely than not percentage threshold | 50.00% | |||
Unrecognized tax benefits | 90 | $ 90 | ||
Unrecognized tax benefits that would impact effective tax rate | 66.6 | 66.6 | ||
Interest expense or penalties, uncertain tax positions | 0.5 | $ 0 | ||
Accrued interest, uncertain tax positions | $ 0.5 | $ 0.5 | $ 0 | $ 0 |
Internal Revenue Service (IRS) [Member] | ||||
Income Tax Contingency [Line Items] | ||||
Earliest year subject to examination | 2,000 |
Income Taxes Effective Tax Rate
Income Taxes Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Effective tax rate reconciliation | ||||
Income Before Income Taxes | $ 34,946 | $ 30,187 | $ 113,988 | $ 130,812 |
Income tax calculated at 35% federal statutory rate | $ 12,231 | $ 10,565 | $ 39,896 | $ 45,784 |
Income tax calculated at 35% federal statutory rate | 35.00% | 35.00% | 35.00% | 35.00% |
State income, net of federal provisions | $ (615) | $ (857) | $ (2,740) | $ (329) |
State income, net of federal provisions | (1.80%) | (2.80%) | (2.40%) | (0.30%) |
Flow-through repairs deductions | $ (18,995) | $ (2,779) | $ (32,640) | $ (17,240) |
Flow-through repairs deductions | (54.40%) | (9.20%) | (28.60%) | (13.20%) |
Production tax credits | $ (2,218) | $ (733) | $ (7,317) | $ (2,645) |
Production tax credits | (6.30%) | (2.40%) | (6.40%) | (2.00%) |
Plant and depreciation of flow through items | $ (243) | $ (374) | $ (1,427) | $ (1,000) |
Plant and depreciation of flow through items | (0.70%) | (1.20%) | (1.30%) | (0.80%) |
Prior year permanent return to accrual adjustments | $ 0 | $ 1,025 | $ (128) | $ 1,025 |
Prior year permanent return to accrual adjustments | 0.00% | 3.40% | (0.10%) | 0.80% |
Other, net | $ 181 | $ (458) | $ 116 | $ (979) |
Other, net | 0.60% | (1.60%) | 0.10% | (0.70%) |
Total Other Reconciling Items | $ (21,890) | $ (4,176) | $ (44,136) | $ (21,168) |
Total Other Reconciling Items | (62.60%) | (13.80%) | (38.70%) | (16.20%) |
Income Tax Expense | $ (9,659) | $ 6,389 | $ (4,240) | $ 24,616 |
Income Tax Expense | (27.60%) | 21.20% | (3.70%) | 18.80% |
Internal Revenue Service (IRS) [Member] | ||||
Effective tax rate reconciliation | ||||
Income tax calculated at 35% federal statutory rate | 35.00% |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016 | Dec. 31, 2015 | |
Goodwill [Line Items] | ||
Change in goodwill | $ 0 | |
Goodwill | 357,586 | $ 357,586 |
Electric [Member] | ||
Goodwill [Line Items] | ||
Goodwill | 243,558 | 243,558 |
Natural gas [Member] | ||
Goodwill [Line Items] | ||
Goodwill | $ 114,028 | $ 114,028 |
Comprehensive Income (Loss) (De
Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Other Comprehensive Income (Loss), before Tax [Abstract] | ||||
Foreign currency translation adjustment | $ 26 | $ 233 | $ (84) | $ 445 |
Reclassification of net gains on derivative instruments | (2,448) | (901) | (2,324) | (1,187) |
Other comprehensive loss | (2,422) | (668) | (2,408) | (742) |
Other Comprehensive Income (Loss), Tax [Abstract] | ||||
Foreign currency translation adjustment | 0 | 0 | 0 | 0 |
Reclassification of net gains on derivative instruments | 942 | 346 | 892 | 452 |
Other comprehensive loss | 942 | 346 | 892 | 452 |
Other comprehensive income (loss), net of tax: | ||||
Foreign currency translation adjustment | 26 | 233 | (84) | 445 |
Reclassification of net gains on derivative instruments | (1,506) | (555) | (1,432) | (735) |
Other comprehensive loss | $ (1,480) | $ (322) | $ (1,516) | $ (290) |
Comprehensive Income (Loss) Bal
Comprehensive Income (Loss) Balance sheet classification (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Statement of Financial Position [Abstract] | ||
Foreign currency translation | $ 1,271 | $ 1,355 |
Derivative instruments designated as cash flow hedges | (10,446) | (9,014) |
Pension and postretirement medical plans | (937) | (937) |
Accumulated other comprehensive loss | $ (10,112) | $ (8,596) |
Comprehensive Income (Loss) Cha
Comprehensive Income (Loss) Changes in AOCI by Component (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Beginning balance | $ (8,596) | |||
Net current-period other comprehensive (loss) income | $ (1,480) | $ (322) | (1,516) | $ (290) |
Ending balance | (10,112) | (10,112) | ||
Interest Rate Derivative Instruments Designated as Cash Flow Hedges | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Beginning balance | (8,940) | (8,496) | (9,014) | (8,316) |
Other comprehensive income before reclassifications | 0 | 0 | 0 | 0 |
Amounts reclassified from AOCI, Interest expense | (1,506) | (555) | (1,432) | (735) |
Net current-period other comprehensive (loss) income | (1,506) | (555) | (1,432) | (735) |
Ending balance | (10,446) | (9,051) | (10,446) | (9,051) |
Pension and Postretirement Medical Plans | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Beginning balance | (937) | (1,247) | (937) | (1,247) |
Other comprehensive income before reclassifications | 0 | 0 | 0 | 0 |
Amounts reclassified from AOCI, Interest expense | 0 | 0 | 0 | 0 |
Net current-period other comprehensive (loss) income | 0 | 0 | 0 | 0 |
Ending balance | (937) | (1,247) | (937) | (1,247) |
Foreign Currency Translation | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Beginning balance | 1,245 | 1,009 | 1,355 | 797 |
Other comprehensive income before reclassifications | 26 | 233 | (84) | 445 |
Amounts reclassified from AOCI, Interest expense | 0 | 0 | 0 | 0 |
Net current-period other comprehensive (loss) income | 26 | 233 | (84) | 445 |
Ending balance | 1,271 | 1,242 | 1,271 | 1,242 |
Total | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Beginning balance | (8,632) | (8,734) | (8,596) | (8,766) |
Other comprehensive income before reclassifications | 26 | 233 | (84) | 445 |
Amounts reclassified from AOCI, Interest expense | (1,506) | (555) | (1,432) | (735) |
Net current-period other comprehensive (loss) income | (1,480) | (322) | (1,516) | (290) |
Ending balance | $ (10,112) | $ (9,056) | $ (10,112) | $ (9,056) |
Risk Management and Hedging A40
Risk Management and Hedging Activities (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016 | Dec. 31, 2015 | |
Derivative [Line Items] | ||
Pre-tax gain on cash flow hedges remaining in AOCL | $ 17,200 | |
Pre-tax gain on cash flow hedge to be reclassified within twelve months from AOCL to interest expense | 600 | |
Physical purchase and sale of gas and electricity at fixed prices | $ 0 | $ 0 |
Number of interest rate derivatives held | 0 | |
Interest Expense [Member] | ||
Derivative [Line Items] | ||
Amount of gain reclassified from AOCL | $ 2,324 |
Fair Value Recurring Basis (Det
Fair Value Recurring Basis (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Fair value, assets, level 1 to level 2 transfers, amount | $ 0 | $ 0 |
Fair value, assets, level 2 to level 1 transfers, amount | 0 | 0 |
Fair value, liabilities, level 1 to level 2 transfers, amount | 0 | 0 |
Fair value, liabilities, level 2 to level 1 transfers, amount | 0 | 0 |
Fair Value, transfers into (out of) level 3 | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 6,350 | 6,240 |
Rabbi trust investments | 25,057 | 24,245 |
Total | 31,407 | 30,485 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs(Level 2) | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 0 | 0 |
Rabbi trust investments | 0 | 0 |
Total | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs(Level 3) | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 0 | 0 |
Rabbi trust investments | 0 | 0 |
Total | 0 | 0 |
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 6,350 | 6,240 |
Rabbi trust investments | 25,057 | 24,245 |
Total | 31,407 | 30,485 |
Margin Cash Collateral Offset | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 0 | 0 |
Rabbi trust investments | 0 | 0 |
Total | $ 0 | $ 0 |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value Finanical Insruments (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, carrying amount | $ 1,794,519 | $ 1,768,183 |
Long-term debt, fair value | $ 1,950,837 | $ 1,844,974 |
Financing Activities (Details)
Financing Activities (Details) - USD ($) $ in Millions | 6 Months Ended | 9 Months Ended |
Jun. 30, 2016 | Sep. 30, 2016 | |
Debt Instrument [Line Items] | ||
Debt Issued By Third Party | $ 144.7 | |
Secured Debt [Member] | Secured Debt South Dakota Due June 2026 [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 60 | |
Interest rate | 2.80% | |
Maturity date | Jun. 15, 2026 | |
Secured Debt [Member] | Secured Debt South Dakota Due 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Interest rate | 6.05% | |
Maturity date | May 1, 2018 | |
Debt instrument, repurchased face amount | $ 55 | |
Secured Debt [Member] | Secured Debt Montana Due 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 144.7 | |
Interest rate | 2.00% | |
Maturity date | Aug. 1, 2023 | |
Secured Debt [Member] | Repurchased Secured Debt Montana Due 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Interest rate | 4.65% | |
Maturity date | Aug. 1, 2023 | |
Debt instrument, repurchased face amount | $ 170.2 | |
Secured Debt [Member] | Secured Debt South Dakota Due September 2026 [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 45 | |
Interest rate | 2.66% | |
Maturity date | Sep. 1, 2026 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | |
Segment Reporting Information [Line Items] | |||||
Operating revenues | $ 300,998 | $ 272,739 | $ 926,657 | $ 889,310 | |
Cost of sales | 96,156 | 73,577 | 293,283 | 265,495 | |
Gross margin | 204,842 | 199,162 | 633,374 | 623,815 | |
Operating, general and administrative | 68,290 | 79,296 | 220,730 | 222,139 | |
Property and other taxes | 40,673 | 35,712 | 111,302 | 100,953 | |
Depreciation and depletion | 39,763 | 35,693 | 119,551 | 107,239 | |
Operating income (loss) | 56,116 | 48,461 | 181,791 | 193,484 | |
Interest expense | (21,049) | (22,043) | (71,979) | (68,101) | |
Other income (loss) | (121) | 3,769 | 4,176 | 5,429 | |
Income Tax Benefit (Expense) | 9,659 | (6,389) | 4,240 | (24,616) | |
Net Income | 44,605 | 23,798 | 118,228 | 106,196 | |
Total assets | 5,393,941 | 5,235,078 | 5,393,941 | 5,235,078 | $ 5,264,695 |
Capital expenditures | 82,752 | 72,154 | 203,998 | 203,324 | |
Electric [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 266,629 | 238,513 | 756,374 | 695,921 | |
Cost of sales | 89,681 | 66,197 | 245,470 | 196,034 | |
Gross margin | 176,948 | 172,316 | 510,904 | 499,887 | |
Operating, general and administrative | 50,460 | 58,298 | 157,471 | 179,191 | |
Property and other taxes | 32,343 | 28,648 | 87,094 | 78,987 | |
Depreciation and depletion | 32,549 | 28,476 | 97,614 | 85,523 | |
Operating income (loss) | 61,596 | 56,894 | 168,725 | 156,186 | |
Interest expense | (19,099) | (19,078) | (65,273) | (58,524) | |
Other income (loss) | 982 | 1,832 | 2,136 | 4,773 | |
Income Tax Benefit (Expense) | 7,946 | (6,553) | 3,600 | (16,364) | |
Net Income | 51,425 | 33,095 | 109,188 | 86,071 | |
Total assets | 4,294,549 | 4,169,423 | 4,294,549 | 4,169,423 | |
Capital expenditures | 66,322 | 57,813 | 165,885 | 171,800 | |
Natural Gas [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 34,369 | 34,226 | 170,283 | 193,389 | |
Cost of sales | 6,475 | 7,380 | 47,813 | 69,461 | |
Gross margin | 27,894 | 26,846 | 122,470 | 123,928 | |
Operating, general and administrative | 19,141 | 19,843 | 61,638 | 63,554 | |
Property and other taxes | 8,328 | 7,062 | 24,200 | 21,958 | |
Depreciation and depletion | 7,206 | 7,209 | 21,913 | 21,691 | |
Operating income (loss) | (6,781) | (7,268) | 14,719 | 16,725 | |
Interest expense | (1,249) | (2,562) | (5,018) | (8,304) | |
Other income (loss) | 345 | 507 | 925 | 1,349 | |
Income Tax Benefit (Expense) | 1,169 | 1,883 | (574) | (1,621) | |
Net Income | (6,516) | (7,440) | 10,052 | 8,149 | |
Total assets | 1,093,333 | 1,057,919 | 1,093,333 | 1,057,919 | |
Capital expenditures | 16,430 | 14,341 | 38,113 | 31,524 | |
All Other Segments [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 0 | 0 | 0 | 0 | |
Cost of sales | 0 | 0 | 0 | 0 | |
Gross margin | 0 | 0 | 0 | 0 | |
Operating, general and administrative | (1,311) | 1,155 | 1,621 | (20,606) | |
Property and other taxes | 2 | 2 | 8 | 8 | |
Depreciation and depletion | 8 | 8 | 24 | 25 | |
Operating income (loss) | 1,301 | (1,165) | (1,653) | 20,573 | |
Interest expense | (701) | (403) | (1,688) | (1,273) | |
Other income (loss) | (1,448) | 1,430 | 1,115 | (693) | |
Income Tax Benefit (Expense) | 544 | (1,719) | 1,214 | (6,631) | |
Net Income | (304) | (1,857) | (1,012) | 11,976 | |
Total assets | 6,059 | 7,736 | 6,059 | 7,736 | |
Capital expenditures | 0 | 0 | 0 | 0 | |
Intersegment Elimination [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 0 | 0 | 0 | 0 | |
Cost of sales | 0 | 0 | 0 | 0 | |
Gross margin | 0 | 0 | 0 | 0 | |
Operating, general and administrative | 0 | 0 | 0 | 0 | |
Property and other taxes | 0 | 0 | 0 | 0 | |
Depreciation and depletion | 0 | 0 | 0 | 0 | |
Operating income (loss) | 0 | 0 | 0 | 0 | |
Interest expense | 0 | 0 | 0 | 0 | |
Other income (loss) | 0 | 0 | 0 | 0 | |
Income Tax Benefit (Expense) | 0 | 0 | 0 | 0 | |
Net Income | 0 | 0 | 0 | 0 | |
Total assets | 0 | 0 | 0 | 0 | |
Capital expenditures | $ 0 | $ 0 | $ 0 | $ 0 |
Earnings Per Share (Details)
Earnings Per Share (Details) - shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Basic computation | 48,314,783 | 47,065,082 | 48,288,678 | 47,028,924 |
Dilutive effect of performance share awards (1) | 154,537 | 245,463 | 154,889 | 245,460 |
Diluted computation | 48,469,320 | 47,310,545 | 48,443,567 | 47,274,384 |
Employee Benefit Plans Net Peri
Employee Benefit Plans Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Pension Benefits [Member] | ||||
Components of Net Periodic Benefit Cost (Income) [Abstract] | ||||
Service cost | $ 2,939 | $ 3,091 | $ 8,819 | $ 9,272 |
Interest cost | 6,553 | 6,544 | 19,658 | 19,631 |
Expected return on plan assets | (7,062) | (7,890) | (21,186) | (23,671) |
Amortization of prior service cost | 62 | 62 | 185 | 185 |
Recognized actuarial loss | 2,472 | 2,659 | 7,416 | 7,976 |
Net Periodic Benefit Cost (Income) | 4,964 | 4,466 | 14,892 | 13,393 |
Other Postretirement Benefits [Member] | ||||
Components of Net Periodic Benefit Cost (Income) [Abstract] | ||||
Service cost | 123 | 132 | 369 | 395 |
Interest cost | 198 | 197 | 596 | 590 |
Expected return on plan assets | (261) | (242) | (782) | (727) |
Amortization of prior service cost | (471) | (471) | (1,412) | (1,412) |
Recognized actuarial loss | 78 | 96 | 236 | 289 |
Net Periodic Benefit Cost (Income) | $ (333) | $ (288) | $ (993) | $ (865) |
Commitments and Contingencies E
Commitments and Contingencies Environmental (Details) $ in Millions | 9 Months Ended | |
Sep. 30, 2016USD ($) | Jul. 01, 2018 | |
Colstrip Unit 4 [Member] | ||
Jointly owned utility plant ownership percentage | 30.00% | |
Environmental obligation, estimated capital Expenditures | $ 90 | |
Coyote Generating Facility [Member] | ||
Jointly owned utility plant ownership percentage | 10.00% | |
Environmental remediation obligations [Member] | ||
Environmental remediation obligation, minimum | $ 27 | |
Environmental remediation obligation, maximum | 32 | |
Accrual for environmental loss contingencies | 30.3 | |
Combined Manufacturing Sites [Member] | Manufactured Gas Plants [Member] | ||
Accrual for environmental loss contingencies | 23.7 | |
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member] | ||
Accrual for environmental loss contingencies | 11.1 | |
Environmental remediation obligation next 5 years | $ 6.5 | |
Number of years for environmental remediation obligation to be incurred | 5 years | |
Scenario, Forecast [Member] | Coyote Generating Facility [Member] | ||
NOx emissions per million Btu as calculated on a 30 day rolling average basis | 0.5 |
Commitments and Contingencies L
Commitments and Contingencies Litigation (Details) - Refinery outage [Member] - USD ($) $ in Millions | 1 Months Ended | 9 Months Ended | 12 Months Ended |
Aug. 31, 2014 | Sep. 30, 2016 | Dec. 31, 2015 | |
Loss Contingencies [Line Items] | |||
Damages sought | $ 48.5 | $ 65.6 | $ 61.7 |
Retention amount | $ 2 |